Naphthenic compositions derived from fcc process fractions

ABSTRACT

Systems and methods are provided for producing naphthenic compositions corresponding to various types of products, such as naphthenic base oil, specialty industrial oils, and/or hydrocarbon fluids. The methods of producing the naphthenic compositions can include exposing a heavy fraction from a fluid catalytic cracking (FCC) process, such as a FCC bottoms fraction (i.e., a catalytic slurry oil), to hydroprocessing conditions corresponding to hydrotreating and/or aromatic saturation conditions. Naphthenic compositions formed from processing of FCC fractions are also provided.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application Ser.No. 62/781,892 filed Dec. 19, 2018, which is herein incorporated byreference in its entirety.

FIELD

Naphthenic compositions derived from fluid catalytic cracking productfractions are provided, along with systems and methods for forming suchnaphthenic compositions. Examples of naphthenic compositions includenaphthenic base oils, specialty industrial oils, and naphthenic and/oraromatic hydrocarbon fluids.

BACKGROUND

Fluid catalytic cracking (FCC) processes are commonly used in refineriesas a method for converting feedstocks, without requiring additionalhydrogen, to produce lower boiling fractions suitable for use as fuels.While FCC processes can be effective for converting a majority of atypical input feed, under conventional operating conditions at least aportion of the resulting products can correspond to a fraction thatexits the process as a “bottoms” fraction. This bottoms fraction cantypically be a high boiling range fraction, such as a ˜650° F.+(˜343°C.+) fraction. Because this bottoms fraction may also contain FCCcatalyst fines, this fraction can sometimes be referred to as acatalytic slurry oil.

U.S. Pat. No. 8,691,076 describes methods for manufacturing naphthenicbase oils from effluences of a fluidized catalytic cracking unit. Themethods describe using an FCC unit to process an atmospheric resid toform a fuels fraction, a light cycle oil fraction, and a slurry oilfraction. Portions of the light cycle oil and/or the slurry oil are thenhydrotreated and dewaxed to form naphthenic base oils. U.S. Pat. No.8,585,889 describes a variation where the slurry oil fraction isdeasphalted prior to hydrotreatment and dewaxing. U.S. Pat. No.8,911,613 describes still other variations where the light cycle oiland/or slurry oil fractions are co-processed in the hydrotreating anddewaxing stages with a deasphalted oil from another source.

U.S. Patent Application Publication 2017/0002279 describes methods forprocessing catalytic slurry oils under fixed bed hydrotreatingconditions. U.S. Patent Application Publication 2017/0002273 describesvarious types of fuels that can be formed based on fixed bedhydrotreatment of catalytic slurry oils.

SUMMARY

In an aspect, a method is provided for processing a product fractionfrom a fluid catalytic cracking (FCC) process. The method can includeexposing a feed comprising a catalytic slurry oil, the feed comprising a343° C.+ portion, to a hydrotreating catalyst under effectivehydrotreating conditions to form a hydrotreated effluent, the 343° C.+portion of the feed comprising a density of 1.06 g/cm3 or more. Themethod can further include exposing at least a portion of the 343° C.+portion to a hydroprocessing catalyst under effective hydroprocessingconditions to form a hydroprocessed effluent, wherein a C5+ portion ofthe hydroprocessed effluent comprises 50 mol % or more naphtheniccarbons and 500 wppm or less of sulfur.

In another aspect, a naphthenic base oil composition is provided thatincludes 500 wppm or less sulfur, 18 mol % to 30 mol % paraffiniccarbons, 50 mol % or more of naphthenic carbons, a kinematic viscosityat 100° C. of 2.0 cSt to 30 cSt, a viscosity index of 25 or less, and aT5 distillation point of 260° C. or more.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 shows an example of a reaction system for forming naphtheniccompositions from a feed comprising a catalytic slurry oil.

FIG. 2 shows an example of a reaction system for forming naphtheniccompositions from a feed comprising a catalytic slurry oil.

FIG. 3 shows an example of a reaction system for forming naphtheniccompositions from a feed comprising a catalytic slurry oil.

FIG. 4 shows an example of a reaction system for forming naphtheniccompositions from a feed comprising a catalytic slurry oil.

FIG. 5 shows an example of a reaction system for forming naphtheniccompositions from a feed comprising a catalytic slurry oil.

FIG. 6 shows viscosity index versus percentage of naphthenic carbon forvarious naphthenic oils formed from naphthenic crude oil feeds andformed from hydroprocessing of catalytic slurry oils.

FIG. 7 shows properties for 3.5 cSt naphthenic base oils afterhydroprocessing under various aromatic saturation conditions.

FIG. 8 shows pour point versus kinematic viscosity at 100° C. forvarious naphthenic oils.

FIG. 9 shows pour point versus kinematic viscosity at 40° C. for variousnaphthenic oils.

FIG. 10 shows percentage of paraffinic carbon versus amount of saturatesfor various naphthenic oils formed from naphthenic crude oil feeds andformed from hydroprocessing of catalytic slurry oils.

DETAILED DESCRIPTION

In various aspects, systems and methods are provided for producingnaphthenic compositions corresponding to various types of products, suchas naphthenic base oil, specialty industrial oils, and/or hydrocarbonfluids. The methods of producing the naphthenic compositions can includeexposing a heavy fraction from a fluid catalytic cracking (FCC) process,such as a FCC bottoms fraction (i.e., a catalytic slurry oil), tohydroprocessing conditions corresponding to hydrotreating and/oraromatic saturation conditions. The hydroprocessing can be performedwithout exposing the FCC heavy fraction to catalytic dewaxingconditions. By using a FCC heavy fraction as a feedstock rather than aconventional feed, naphthenic product compositions can be formed thathave unexpected properties, such as compositions with unexpectedly lowviscosity index values relative to the naphthenic carbon content of thecompositions. Additionally, by minimizing or avoiding exposure of theFCC heavy fraction feedstock to catalytic dewaxing conditions,naphthenic product compositions can be formed that have unexpectedcombinations of pour point, kinematic viscosity, and viscosity indexrelative to the amount of naphthenic carbon in the composition.

Catalytic slurry oils (or other names used to refer to FCC bottomsfractions) are high sulfur and high aromatic content fractions generatedduring FCC processing. Catalytic slurry oils typically have an initialboiling point and/or T5 distillation point of 343° C. or more. The finalboiling point and/or T95 distillation point can vary, but is commonly565° C. or more. Traditionally, the product disposition for catalyticslurry oil is to use the catalytic slurry oil as a blend component forforming regular sulfur fuel oils, or as feedstock for formation ofcarbon black. Due in part to upcoming and/or planned changes inregulations for sulfur content in fuel oils, however, alternativedispositions for catalytic slurry oils are desirable.

Based on the highly aromatic nature of catalytic slurry oils, somepossible alternative dispositions correspond to using catalytic slurryoils as a feedstock for production of aromatic products or naphthenicproducts. However, catalytic slurry oils can also contain up to 6.0 wt %or more of sulfur as well as substantial amounts of nitrogen. Methodsfor removing such heteroatoms while preserving the desiredaromatic/naphthenic character of the catalytic slurry oil are needed inorder to produce commercially viable products.

It has been unexpectedly discovered that catalytic slurry oil can beused to make a variety of naphthenic product compositions that aretraditionally made from higher value feeds, such as naphthenic crudeoils. In various aspects, single stage or (preferably) multi-stagehydroprocessing of catalytic slurry oil can be used to form naphthenicproduct compositions. By adjusting the processing conditions, includingoptionally performing aromatic saturation and/or solvent processing,naphthenic hydrocarbon mixtures can be produced with desirablecombinations of compositional and physical properties, such ashydrocarbon mixtures with high naphthenic carbon content, low sulfurcontent, and targeted values for viscosity and/or viscosity index.

In various aspects, any convenient number of hydroprocessing stages canbe used for the hydrotreatment and/or aromatic saturation of the FCCheavy fraction. For example, single stage hydrotreatment may be suitablefor forming an effluent containing less than 250 wppm sulfur and 50 wt %to 75 wt % aromatics. Various naphthenic compositions can then be formedfrom such an effluent, including naphthenic compositions having akinematic viscosity at 100° C. of 2.5 cSt to 35 cSt. Such naphtheniccompositions can include 50 wt % to 90 wt % aromatics. Of course, anyconvenient number of hydrotreatment stages could be used to make such aneffluent. As another example, multi-stage hydroprocessing may besuitable for forming an effluent containing less than 250 wppm sulfurand 60 wt % or more naphthenes (or 70 wt % or more). Optionally, thefirst stage for forming such a hydroprocessing effluent can correspondto a hydrotreatment stage, while the second stage can correspond to anaromatic saturation stage. Various naphthenic compositions can then beformed from such a hydroprocessing effluent, including naphtheniccompositions having a kinematic viscosity at 100° C. of 2.0 cSt to 100cSt, or 2.5 cSt or 50 cSt. Of course, any convenient number ofhydroprocessing stages could be used to make such a hydroprocessedeffluent.

In various aspects, the naphthenic compositions can have unexpectedcombinations of naphthenic carbon content and viscosity index.Naphthenic carbon content refers to the number of carbon atomsparticipating in naphthenic bonding (i.e., saturated ring bonding). Thisis in contrast to paraffinic carbons (alkane type bonding) and aromaticcarbons (carbon atoms that are part of a pi-bond system). The amount ofnaphthenic carbon, paraffinic carbon, and/or aromatic carbon can bedetermined by ASTM D2140. In some aspects, a naphthenic composition caninclude 60 mol % or more naphthenic carbons, relative to the totalamount of carbon, or 65 mol % or more, or 70 mol % or more, such as upto 80 mol % or possibly still higher. In such aspects, the viscosityindex of the naphthenic composition can be −200 to 50, or −150 to 35.This combination of naphthenic carbon content and viscosity index is incontrast to naphthenic compositions formed from a conventional source,such as a naphthenic crude. Naphthenic compositions formed fromnaphthenic crudes typically have less than 60 mol % naphthenic carbons.Additionally or alternately, the amount of paraffinic carbon can be 30mol % or less, or 25 mol % or less, such as down to 18 mol % or possiblystill lower. Optionally, in such aspects, the amount of saturates in thenaphthenic composition can be 50 wt % or more, or 60 wt % or more, or 70wt % or more, such as up to 99.8 wt % saturates or possibly stillhigher. Conventionally, naphthenic oils made from conventional feedsinclude 34 mol % or more of paraffinic carbons. Optionally, the effluentcan also contain 15 mol % or less aromatic carbon, or 10 mol % or less,or 5.0 mol % or less, such as down to 1.0 mol % or possibly still lower.

In this discussion, an FCC bottoms fraction can be referred to as acatalytic slurry oil. Catalytic slurry oil is defined herein to alsorefer to FCC fractions that substantially correspond to an FCC bottomsfraction. An FCC fraction that substantially corresponds to an FCCbottoms fraction is defined to include FCC fractions that have a T5 toT95 boiling range that is within the typical boiling range for an FCCbottoms fraction, even if the fraction was formed via a distillationprocess that generated another higher boiling fraction. It is noted thatwhen initially formed, a catalytic slurry oil can include several weightpercent of catalyst fines. Such catalyst fines can optionally butpreferably be removed (such as partially removed to a desired level) byany convenient method, such as filtration. In this discussion, unlessotherwise explicitly noted, references to a catalytic slurry oil aredefined to include catalytic slurry oil either prior to or after such aprocess for reducing the content of catalyst fines within the catalyticslurry oil.

As defined herein, the term “hydrocarbonaceous” includes compositions orfractions that contain hydrocarbons and hydrocarbon-like compounds thatmay contain heteroatoms typically found in petroleum or renewable oilfraction and/or that may be typically introduced during conventionalprocessing of a petroleum fraction. Heteroatoms typically found inpetroleum or renewable oil fractions include, but are not limited to,sulfur, nitrogen, phosphorous, and oxygen. Other types of atomsdifferent from carbon and hydrogen that may be present in ahydrocarbonaceous fraction or composition can include alkali metals aswell as trace transition metals (such as Ni, V, or Fe).

In some aspects, reference may be made to conversion of a feedstockrelative to a conversion temperature. Conversion relative to atemperature can be defined based on the portion of the feedstock thatboils at greater than the conversion temperature. The amount ofconversion during a process (or optionally across multiple processes)can correspond to the weight percentage of the feedstock converted fromboiling above the conversion temperature to boiling below the conversiontemperature. As an illustrative hypothetical example, consider afeedstock that includes 40 wt % of components that boil at 700° F.(˜371° C.) or greater. By definition, the remaining 60 wt % of thefeedstock boils at less than 700° F. (˜371° C.). For such a feedstock,the amount of conversion relative to a conversion temperature of ˜371°C. would be based only on the 40 wt % that initially boils at ˜371° C.or greater. If such a feedstock could be exposed to a process with 30%conversion relative to a ˜371° C. conversion temperature, the resultingproduct would include 72 wt % of ˜371° C.− components and 28 wt % of˜371° C.+ components.

All numerical values within the detailed description and the claimsherein are modified by “about” or “approximately” the indicated value,and take into account experimental error and variations that would beexpected by a person having ordinary skill in the art.

Feedstock—Catalytic Slurry Oil

A catalytic slurry oil can correspond to a high boiling fraction, suchas a bottoms fraction, from an FCC process. A feed including a catalyticslurry oil can correspond to a feed that includes 50 wt % or more of acatalytic slurry oil, or 75 wt % or more, or 90 wt % or more, such as upto 100 wt %. A variety of properties of a catalytic slurry oil can becharacterized to specify the nature of a catalytic slurry oil feed.

One aspect that can be characterized corresponds to a boiling range ofthe catalytic slurry oil. Typically the cut point for forming acatalytic slurry oil can be 650° F. (˜343° C.) or more. As a result, acatalytic slurry oil can have a T5 distillation (boiling) point or a T10distillation point of 650° F. (˜343° C.) or more, as measured accordingto ASTM D2887. In some aspects the D2887 10% distillation point can begreater, such as 675° F. (˜357° C.) or more, or 700° F. (˜371° C.) ormore. In some aspects, a broader boiling range portion of FCC productscan be used as a feed (e.g., a 350° F.+/˜177° C.+ boiling range fractionof FCC liquid product), where the broader boiling range portion includesa 650° F.+(˜343° C.+) fraction that corresponds to a catalytic slurryoil. The catalytic slurry oil (650° F.+/˜343° C.+) fraction of the feeddoes not necessarily have to represent a “bottoms” fraction from an FCCprocess, so long as the catalytic slurry oil portion comprises one ormore of the other feed characteristics described herein.

In addition to and/or as an alternative to initial boiling points, T5distillation point, and/or T10 distillation points, other distillationpoints may be useful in characterizing a feedstock. For example, afeedstock can be characterized based on the portion of the feedstockthat boils above 1050° F. (˜566° C.). In some aspects, a feedstock (oralternatively a 650° F.+/˜343° C.+ portion of a feedstock) can have anASTM D2887 T95 distillation point of 1050° F. (˜566° C.) or more, or aT90 distillation point of 1050° F. (˜566° C.) or more. Additionally oralternately, the T95 distillation point and/or the final boiling pointcan be 1200° F. (˜650° C.) or less, or 1150° F. (˜620° C.) or less. If afeedstock or other sample contains components that are not suitable forcharacterization using D2887, ASTM D1160 may be used instead for suchcomponents.

In various aspects, density, or weight per volume, of the catalyticslurry oil can be characterized. The density of the catalytic slurry oil(or alternatively a 650° F.+/˜343° C.+ portion of a feedstock) can be1.06 g/cm3 or more, or 1.08 g/cm3 or more, or 1.10 g/cm3 or more, suchas up to about 1.20 g/cm3 or possibly still higher (ASTM D4052). Thedensity of the catalytic slurry oil can provide an indication of theamount of heavy aromatic cores that are present within the catalyticslurry oil. A lower density catalytic slurry oil feed can in someinstances correspond to a feed that may have a greater expectation ofbeing suitable for hydrotreatment without substantial and/or rapid cokeformation.

Contaminants such as nitrogen and sulfur are typically found incatalytic slurry oils, often in organically-bound form. Nitrogen contentcan range from 50 wppm to 5000 wppm elemental nitrogen, or 100 wppm to2000 wppm elemental nitrogen, or 250 wppm to 1000 wppm, based on totalweight of the catalytic slurry oil. The nitrogen containing compoundscan be present as basic or non-basic nitrogen species. Examples ofnitrogen species can include quinolines, substituted quinolines,carbazoles, and substituted carbazoles.

The sulfur content of a catalytic slurry oil feed can be 500 wppm ormore elemental sulfur, based on total weight of the catalytic slurryoil. Generally, the sulfur content of a catalytic slurry oil can rangefrom 500 wppm to 100,000 wppm elemental sulfur, or from 1000 wppm to50,000 wppm, or from 1000 wppm to 30,000 wppm, based on total weight ofthe heavy component. Sulfur can usually be present as organically boundsulfur. Examples of such sulfur compounds include the class ofheterocyclic sulfur compounds such as thiophenes, tetrahydrothiophenes,benzothiophenes and their higher homologs and analogs. Other organicallybound sulfur compounds include aliphatic, naphthenic, and aromaticmercaptans, sulfides, di- and polysulfides.

Catalytic slurry oils can include n-heptane insolubles (NHI) orasphaltenes. In some aspects, the catalytic slurry oil feed (oralternatively a ˜650° F.+/˜343° C.+ portion of a feed) can contain 1.0wt % or more of n-heptane insolubles or asphaltenes, or 3.0 wt % ormore, or 5.0 wt % or more, such as up to 10 wt % or possibly stillhigher. Another option for characterizing the heavy components of acatalytic slurry oil can be based on the amount of micro carbon residue(MCR) in the feed. In various aspects, the amount of MCR in thecatalytic slurry oil feed (or alternatively a ˜343° C.+ portion of afeed) can be 5 wt % or more, or 8 wt % or more, or 10 wt % or more, suchas up to 15 wt % or possibly still higher.

Catalytic slurry oil fractions are typically formed by atmosphericfractionation of the effluent from an FCC reactor. For example, afterperforming an FCC process on a feed, the resulting FCC effluent istypically fractionated in one or more separation stages. The one or moreseparation stages can correspond to an atmospheric distillation unit, orthe one or more separation stages can correspond to a plurality ofindividual separations that have roughly a similar effect as using anatmospheric distillation unit. The lower boiling fractions generated byfractionation of an FCC effluent correspond to the typical desiredproducts from FCC processing, such as a light ends/olefin-containingfraction, a naphtha fraction, and one or more cycle oils that canoptionally be further upgraded for use as distillate fuel. The “bottoms”cut from the fractionation of the FCC effluent corresponds to thecatalytic slurry oil.

Due to the nature of fluid catalytic cracking processes, catalyst finesare typically generated during such processes. These catalyst fines tendto be segregated into the bottoms fraction during the atmosphericfractionation, resulting in formation of a catalytic slurry oil. Priorto hydroprocessing of a catalytic slurry oil in a reaction that includesfixed catalyst beds (such as trickle beds), it can be beneficial toremove the catalyst fines so that the catalyst fines do not contributeto plugging or channeling in the catalyst bed. The feedstock, after anyoptional treatment in a particle removal stage, can have a particlecontent of about 500 wppm or less of particles having a size of 25 μm ormore, or about 100 wppm or less, or about 50 wppm or less, or about 20wppm or less, such as down to substantially no content of suspendedsolids (˜0 wppm). Filtration is an example of a suitable method forremoving the catalyst fines, although other methods can also be used inaddition to or in place of filtration. Examples of other methodsinclude, but are not limited to, gravity settling, electrostaticfiltration, and centrifugation. For example, particles can be removed byfirst performing gravity settling, and then passing the effluent fromthe gravity settler through a filter available from Mott Corporation orthrough an electrostatic filter available from Gulftronic. Afterremoving particles in the catalytic slurry oil to a desired level, thefeed can be hydroprocessed.

In some aspects, an alternative to performing filtration can be to usefractionation and/or solvent processing to remove catalyst fines fromthe feed. In other aspects, filtration can be performed in combinationwith fractionation and/or solvent processing. Thus, solvent processingand/or fractionation can potentially be performed prior to, during,and/or after the hydroprocessing of the feed including catalytic slurryoil. In addition to removing particles, performing fractionation and/orsolvent processing can also remove a portion of the higher boilingcomponents in the feed. If vacuum fractionation is used withoutfiltration, the catalyst fines can be segregated into the vacuum bottomsfraction. If solvent deasphalting is used without filtration, thecatalyst fines can be segregated into the residual or rock fraction.

Solvent deasphalting is an example of a solvent extraction process. Insome aspects, suitable solvents for solvent deasphalting include alkanesor other hydrocarbons (such as alkenes) containing 4 to 7 carbons permolecule. Examples of suitable solvents include n-butane, isobutane,n-pentane, C4+ alkanes, C5+ alkanes, C4+ hydrocarbons, and C5+hydrocarbons. In other aspects, suitable solvents can include C3hydrocarbons, such as propane. In such other aspects, examples ofsuitable solvents include propane, n-butane, isobutane, n-pentane, C3+alkanes, C4+ alkanes, C5+ alkanes, C3+ hydrocarbons, C4+ hydrocarbons,and C5+ hydrocarbons.

A deasphalting process typically corresponds to contacting a heavyhydrocarbon feed (such as a feed including catalytic slurry oil) with analkane solvent (propane, butane, pentane, hexane, heptane etc and theirisomers), either in pure form or as mixtures, to produce two types ofproduct streams. One type of product stream corresponds to a deasphaltedoil extracted by the alkane, which is further separated to producedeasphalted oil stream. A second type of product stream is the residualportion of the feed not soluble in the solvent (i.e., a raffinate).Conventionally, the residual product from solvent deasphalting can bereferred to as a rock or asphaltene fraction. The deasphalted oilfraction can be hydroprocessed. The rock fraction can potentially beused as a blend component to produce asphalt, fuel oil, and/or otherproducts. The rock fraction can also be used as feed to gasificationprocesses such as partial oxidation, fluid bed combustion or cokingprocesses. The rock can be delivered to these processes as a liquid(with or without additional components) or solid (either as pellets orlumps).

During solvent deasphalting, the feed can be mixed with a solvent.Portions of the feed that are soluble in the solvent are then extracted,leaving behind a residue with little or no solubility in the solvent.The portion of the deasphalted feedstock that is extracted with thesolvent is often referred to as deasphalted oil. Typical solventdeasphalting conditions include mixing a feedstock fraction with asolvent in a weight ratio of from about 1:2 to about 1:10, such as about1:8 or less. Typical solvent deasphalting temperatures range from 40° C.to 200° C., or 40° C. to 150° C., depending on the nature of the feedand the solvent. The pressure during solvent deasphalting can be fromabout 50 psig (345 kPag) to about 500 psig (3447 kPag).

It is noted that the above solvent deasphalting conditions represent ageneral range, and the conditions will vary depending on the feed. Forexample, under typical deasphalting conditions, increasing thetemperature can tend to reduce the yield of DAO while increasing thequality of the resulting deasphalted oil. Under typical deasphaltingconditions, increasing the molecular weight of the solvent can tend toincrease the yield while reducing the quality of the resultingdeasphalted oil, as additional compounds within a resid fraction may besoluble in a solvent composed of higher molecular weight hydrocarbons.Under typical deasphalting conditions, increasing the amount of solventcan tend to increase the yield of the resulting deasphalted oil. Asunderstood by those of skill in the art, the conditions for a particularfeed can be selected based on the resulting yield of deasphalted oilfrom solvent deasphalting. Because catalytic slurry oils often arecomposed of primarily 1050° F.− components, the yield of deasphalted oilcan be quite high, such as 70 wt % to 95 wt %, or 70 wt % to 98 wt %.

Hydroprocessing of Catalytic Slurry Oil to form Naphthenic ProductCompositions

In various aspects, a feed including catalytic slurry oil can behydroprocessed to form one or more naphthenic product compositions. Anexample of a suitable type of hydroprocessing can be hydrotreatment,such as hydrotreatment under trickle bed conditions. Hydrotreatment canoptionally be used in conjunction with other hydroprocessing, such as anaromatic saturation process. However, in various aspects, thehydroprocessing can be performed without exposing the feed containingcatalytic slurry oil to dewaxing conditions. Optionally, the feedincluding catalytic slurry oil can also be solvent processed,fractionated, or a combination thereof. The optional solventprocessing/fractionation can be performed prior to hydroprocessing,between hydroprocessing stages, and/or after hydroprocessing.

In various aspects, a feed including catalytic slurry oil can behydrotreated under effective hydrotreating conditions to form ahydrotreated effluent. In some aspects, the hydrotreating conditions canbe selected to achieve a desired level of sulfur removal, such asreducing the sulfur content in the liquid portion of the hydrotreatedeffluent to 250 wppm or less, or 150 wppm or less, or 100 wppm or less,or 50 wppm or less. In some aspects, the hydrotreating conditions can beselected to achieve a desired level of nitrogen removal, such asreducing the nitrogen content in the liquid portion of the hydrotreatedeffluent to 250 wppm or less, or 150 wppm or less, or 100 wppm or less,or 50 wppm or less. The amount of aromatics remaining in thehydrotreated effluent after reducing the sulfur to 250 wppm or less canbe 50 wt % to 80 wt %, or 60 wt % to 80 wt %.

Optionally, the effective hydrotreating conditions can be selected toallow for reduction of the n-heptane asphaltene content of thehydrotreated effluent to less than about 1.0 wt %, or less than about0.5 wt %, or less than about 0.1 wt %, and optionally down tosubstantially no remaining n-heptane asphaltenes. Additionally oralternately, the effective hydrotreating conditions can be selected toallow for reduction of the micro carbon residue content of thehydrotreated effluent to less than about 2.5 wt %, or less than about1.0 wt %, or less than about 0.5 wt %, or less than about 0.1 wt %, andoptionally down to substantially no remaining micro carbon residue.

Additionally or alternately, in various aspects, the processingconditions can be selected to achieve a desired level of conversion of afeedstock, such as conversion relative to a conversion temperature of˜700° F. (˜371° C.). For example, the process conditions can be selectedto achieve 40% or more conversion of the 1050° F.+(˜566° C.+) portion ofthe feedstock to 1050° F.− (˜566° C.)− components, or 50 wt % or more,or 60 wt % or more, such as up to 80 wt % or possibly still higher.

Hydroprocessing (such as hydrotreating) can be carried out in thepresence of hydrogen. A hydrogen stream can be fed or injected into avessel or reaction zone or hydroprocessing zone corresponding to thelocation of a hydroprocessing catalyst. Hydrogen, contained in ahydrogen “treat gas,” can be provided to the reaction zone. Treat gas,as referred to herein, can be either pure hydrogen or ahydrogen-containing gas stream containing hydrogen in an amount that forthe intended reaction(s). Treat gas can optionally include one or moreother gasses (e.g., nitrogen and light hydrocarbons such as methane)that do not adversely interfere with or affect either the reactions orthe products. Impurities, such as H2S and NH3 are undesirable and cantypically be removed from the treat gas before conducting the treat gasto the reactor. In aspects where the treat gas stream can differ from astream that substantially consists of hydrogen (i.e, at least about 99vol % hydrogen), the treat gas stream introduced into a reaction stagecan contain at least about 50 vol %, or at least about 75 vol %hydrogen, or at least about 90 vol % hydrogen.

During hydrotreatment, a feedstream can be contacted with ahydrotreating catalyst under effective hydrotreating conditions whichinclude temperatures in the range of 450° F. to 800° F. (˜232° C. to˜427° C.), or 500° F. to 750° F. (˜260° C. to ˜399° C.); pressures inthe range of 1.5 MPa-g to 20.8 MPa-g (˜200 to ˜3000 psig), or 3.4 MPa-gto 17.2 MPa-g (˜500 to ˜2500 psig), or 6.9 MPa-g to 17.25 MPa-g (˜1000psig to ˜2500 psig); a liquid hourly space velocity (LHSV) of from 0.1to 10 hr-1, or 0.1 to 5 hr-1; and a hydrogen treat gas rate of from 430to 2600 Nm3/m3 (˜2500 to ˜15000 SCF/bbl), or 850 to 1700 Nm3/m3 (˜5000to ˜10000 SCF/bbl).

In an aspect, the hydrotreating step may comprise at least onehydrotreating reactor, and optionally may comprise two or morehydrotreating reactors arranged in series flow. A vapor separation drumcan optionally be included after each hydrotreating reactor to removevapor phase products from the reactor effluent(s). The vapor phaseproducts can include hydrogen, H2S, NH3, and hydrocarbons containingfour (4) or less carbon atoms (i.e., “C4− hydrocarbons”). The C5+hydrocarbons can be subsequently cooled to form liquid products, andtherefore the C5+ portion of the effluent can be referred to as theliquid portion of the effluent. The effective hydrotreating conditionscan be suitable for removal of 70 wt % or more, or 80 wt % or more, or90 wt % or more of the sulfur content in the feedstream from theresulting liquid products. Additionally or alternately, 50 wt % or more,or 75 wt % or more of the nitrogen content in the feedstream can beremoved from the resulting liquid products.

Hydrotreating catalysts suitable for use herein can include thosecontaining at least one Group VIA metal and at least one Group VIIImetal, including mixtures thereof. Examples of suitable metals includeNi, W, Mo, Co and mixtures thereof, for example CoMo, NiMoW, NiMo, orNiW. These metals or mixtures of metals are typically present as oxidesor sulfides on refractory metal oxide supports. The amount of metals forsupported hydrotreating catalysts, either individually or in mixtures,can range from ˜0.5 to ˜35 wt %, based on the weight of the catalyst.Additionally or alternately, for mixtures of Group VIA and Group VIIImetals, the Group VIII metals can be present in amounts of from ˜0.5 to˜5 wt % based on catalyst, and the Group VIA metals can be present inamounts of from 5 to 30 wt % based on the catalyst. A mixture of metalsmay also be present as a bulk metal catalyst wherein the amount of metalcan comprise ˜30 wt % or greater, based on catalyst weight.

Suitable metal oxide supports for the hydrotreating catalysts includeoxides such as silica, alumina, silica-alumina, titanic, or zirconia.Examples of aluminas suitable for use as a support can include porousaluminas such as gamma or eta. In some aspects where the support cancorrespond to a porous metal oxide support, the catalyst can have anaverage pore size (as measured by nitrogen adsorption) of 30 Å to 1000Å, or 50 Å to 500 Å, or 60 Å to 300 Å. Pore diameter can be determined,for example, according to ASTM Method D4284-07 Mercury Porosimetry.Additionally or alternately, the catalyst can have a surface area (asmeasured by the BET method) of 100 to 350 m2/g, or 150 to 250 m2/g. Insome aspects, a supported hydrotreating catalyst can have the form ofshaped extrudates. The extrudate diameters can range from 1/32nd to ⅛thinch (˜0.7 to ˜3.0 mm), from 1/20th to 1/10th inch (˜1.3 to ˜2.5 mm), orfrom 1/20th to 1/16th inch (˜1.3 to ˜1.5 mm). The extrudates can becylindrical or shaped. Non-limiting examples of extrudate shapes includetrilobes and quadralobes.

Optionally, more than one hydrotreating stage can be used, such ashaving multiple reactors containing hydrotreating catalyst with aseparation stage in between. In such aspects, a portion of thehydrodesulfurization and/or hydrodenitrogenation can be performed in asecond hydrotreating stage. Optionally, such a second hydrotreatingstage can be operated under aromatic saturation conditions.

Aromatic saturation conditions can be similar to hydrotreatingconditions, but the aromatic saturation conditions can be selectedseparately (if desired) from the hydrotreating conditions. Preferably, aseparation stage can be located between the aromatic saturation stageand any hydrotreating stages that perform substantial removal of sulfurfrom the feed. The separation stage can be used to remove H2S, NH3, andC4− hydrocarbons from the feed after hydrotreating. In other aspects, aseparation may not be performed, so that the effluent may be contactedwith an aromatics saturation catalyst with or without the removal ofH2S, NH3 and C4− components. During aromatic saturation, a feedstream(such as a portion of a hydrotreated effluent) can be contacted with anaromatic saturation catalyst under effective aromatic saturationconditions which include temperatures in the range of 390° F. to 800° F.(˜232° C. to ˜427° C.), or 390° F. to 750° F. (˜260° C. to ˜399° C.);pressures in the range of 1.5 MPa-g to 20.8 MPa-g (˜200 to ˜3000 psig),or 3.4 MPa-g to 17.2 MPa-g (˜500 to ˜2500 psig), or 6.9 MPa-g to 17.25MPa-g (˜1000 psig to ˜2500 psig); a liquid hourly space velocity (LHSV)of from 0.1 to 10 hr-1, or 0.1 to 5 hr-1; and a hydrogen treat gas rateof from 430 to 2600 Nm3/m3 (˜2500 to ˜15000 SCF/bbl), or 850 to 1700Nm3/m3 (˜5000 to ˜10000 SCF/bbl).

Hydrofinishing and/or aromatic saturation catalysts can includecatalysts containing Group VI metals, Group VIII metals, and mixturesthereof. In some aspects, hydrotreating catalysts can be used asaromatic saturation catalysts. In some aspects, an aromatic saturationcatalyst can include a Group VIII noble metal, such as Pt, Pd, or acombination thereof. For supported aromatic saturation catalysts,suitable support materials include amorphous or crystalline oxidematerials such as alumina, silica, and silica-alumina. The supportmaterials may also be modified, such as by halogenation, or inparticular fluorination. The metal content of the catalyst can be ashigh as about 20 weight percent for non-noble metals. In some aspects,an aromatic saturation catalyst can include a crystalline materialbelonging to the M41S class or family of catalysts. The M41S family ofcatalysts are mesoporous materials having high silica content. Examplesinclude MCM-41, MCM-48 and MCM-50. A preferred member of this class isMCM-41.

The effective hydrotreating conditions and/or aromatic saturationconditions can optionally be suitable for incorporation of a substantialamount of additional hydrogen into the hydrotreated effluent. Duringhydrotreatment and/or aromatic saturation, the consumption of hydrogenby the feed in order to form the hydrotreated effluent can correspond to1000 SCF/bbl (˜260 Nm3/m3) or more of hydrogen, or 1500 SCF/bbl (˜290Nm3/m3) or more, or 2000 SCF/bbl (˜330 Nm3/m3) or more, or 2200 SCF/bbl(˜370 Nm3/m3) or more, such as up to 5000 SCF/bbl (˜850 Nm3/m3) orpossibly still higher.

In various aspects, the feed including catalytic slurry oil can behydroprocessed without exposing the feed to catalytic dewaxingconditions. For example, the hydroprocessing conditions can be selectedto avoid exposing the feed to dewaxing catalyst and/or dewaxingconditions where dewaxing is performed primarily by isomerization. Insome aspects, such dewaxing catalysts that cause dewaxing primarily byisomerization can correspond to, for example, catalysts that includezeotype frameworks with a unidimensional pore structure. Additionally oralternately, such catalysts can include 10-member ring pore zeolites,such as EU-1, ZSM-35 (or ferrierite), ZSM-11, ZSM-57, NU-87, SAPO-11,and ZSM-22. Such dewaxing catalysts can include a metal hydrogenationcomponent. The metal hydrogenation component can typically be a Group 6and/or a Group 8-10 metal, such as a Group 8-10 noble metal. Forexample, the metal hydrogenation component can be Pt, Pd, or a mixturethereof. Alternatively, the metal hydrogenation component can be acombination of a non-noble Group 8-10 metal with a Group 6 metal.Suitable combinations can include Ni, Co, or Fe with Mo or W, preferablyNi with Mo or W.

Product Properties—Hydrotreated Effluent

The intermediate and/or final products from processing of catalyticslurry oil can be characterized in various manners. One type of productthat can be characterized can be the hydrotreated effluent derived fromhydrotreatment of a catalytic slurry oil feed (or a feed substantiallycomposed of catalytic slurry oil). Additionally or alternately, thehydrotreated effluent derived from hydrotreatment of a catalytic slurryoil feed (or a feed substantially composed of a catalytic slurry oil)may be fractionated into light ends, naphtha, distillate and, residualrange portions prior to characterization.

After hydrotreatment, the liquid (C5+) portion of the hydrotreatedeffluent can have a volume of 95% or more of the volume of the catalyticslurry oil feed, or 100% or more of the volume of the feed, or 105% ormore, or 110% or more, such as up to 150% of the volume or possiblystill higher.

After hydrotreatment, the boiling range of the liquid (C5+) portion ofthe hydrotreated effluent can be characterized in various manners. Insome aspects, the total liquid product can have a T50 distillation pointof 320° C. to 400° C., or 350° C. to 380° C. In some aspects, the totalliquid product can have a T90 distillation point of 450° C. to 525° C.In some aspects, the total liquid product can have a T10 distillationpoint of 250° C. or more, which can reflect the low amount of conversionthat occurs during hydroprocessing of higher boiling compounds to C5+compounds with a boiling point below 200° C. In some aspects, the(weight) percentage of the liquid (C5+) portion that comprises adistillation point greater than about ˜566° C. can be 10 wt % or less,or 5.0 wt % or less, or 2.0 wt % or less, or 1.0 wt % or less, such asdown to 0.05 wt % or less (i.e., substantially no compounds with adistillation point greater than about 1050° F./˜566° C.). Additionallyor alternately, the (weight) percentage of the liquid portion thatcomprises a distillation point less than about −370° C. can be 40 wt %or more, or 50 wt % or more, or 60 wt % or more, such as up to 90 wt %or possibly still higher.

In some aspects, the density (at 15° C.) of the liquid (C5+) portion ofthe hydrotreated effluent can be 1.05 g/cm3 or less, or 1.00 g/cm3 orless, or 0.95 g/cm3 or less, such as down to 0.88 g/cc or lower. Thesulfur content of the liquid (C5+) portion of the hydrotreated effluentcan be 1000 wppm or less, or 500 wppm or less, or 100 wppm or less, suchas down to substantially no remaining sulfur (−1 wppm or possiblylower). The micro carbon residue of the liquid (C5+) portion of thehydrotreated effluent can be 4.0 wt % or less, or 2.0 wt % or less, or1.0 wt % or less, such as substantially complete removal of micro carbonresidue.

The aromatics content of the liquid (C5+) portion of the hydrotreatedeffluent can vary depending on the severity of the hydroprocessing.Generally, the aromatics content can range from substantially noaromatics (˜0 wt %, or alternatively 1.0 wt % or less) to 30 wt %. Insome aspects, the liquid portion of the hydrotreated effluent can havean aromatics content of 0 wt % to 30 wt %, or 0 wt % to 20 wt %, or 0 wt% to 10 wt %. In such aspects with lower aromatics content, thenaphthene content of the liquid portion of the hydrotreated effluent canbe 70 wt % to 98 wt %, or 70 wt % to 90 wt %, or 80 wt % to 98 wt %.

For compositions with a T5 distillation point of 343° C. or more and anaromatics content of 30 wt % or less, or 30 wt % or less, or 20 wt % orless, the amount of naphthenic carbon in the composition can also becharacterized. For example, a naphthenic composition can include 60 mol% or more naphthenic carbons, relative to the total amount of carbon, or65 mol % or more, or 70 mol % or more. In such aspects, the viscosityindex of the naphthenic composition can be −200 to 50, or −150 to 35.

One or more products can also be further fractionated to form narrowboiling range hydrocarbon fluids. For example, at least a portion of thediesel product (177° C. to 343° C.) can be fractionated to formhydrocarbon fluids. The hydrocarbon fluids can be formed to have adesired boiling range, a desired average carbon number, and/or anothertarget property.

As examples of fractions that can be formed, in some aspects anaphthenic base oil composition can be formed that includes a kinematicviscosity at 100° C. of 1.5 cSt to 4.0 cSt, a viscosity index of −20 to25, and a T5 distillation point of 270° C. or more. As another example,a naphthenic base oil composition can be formed that includes akinematic viscosity at 100° C. of 4.5 cSt to 8.0 cSt, a viscosity indexof −50 to 0, and a T5 distillation point of 300° C. or more. As anotherexample, a naphthenic base oil composition can be formed that includes akinematic viscosity at 100° C. of 8.0 cSt to 20 cSt, a viscosity indexof −80 to −20, and a T5 distillation point of 330° C. or more. As stillanother example, a naphthenic base oil composition can be formed thatincludes a kinematic viscosity at 100° C. of 25 cSt to 75 cSt, aviscosity index of −120 to −50, and a T5 distillation point of 360° C.or more.

In various aspects, reference may be made to one or more types offractions generated during distillation of a petroleum feedstock. Suchfractions may include naphtha fractions, kerosene fractions, dieselfractions, and vacuum gas oil fractions. Each of these types offractions can be defined based on a boiling range, such as a boilingrange that includes at least −90 wt % of the fraction, or at least −95wt % of the fraction. For example, for many types of naphtha fractions,at least ˜90 wt % of the fraction, or at least ˜95 wt %, can have aboiling point in the range of ˜85° F. (˜29° C.) to ˜350° F. (˜177° C.).For some heavier naphtha fractions, at least ˜90 wt % of the fraction,and preferably at least ˜95 wt %, can have a boiling point in the rangeof ˜85° F. (˜29° C.) to ˜400° F. (˜204° C.). For a diesel fraction, atleast ˜90 wt % of the fraction, and preferably at least ˜95 wt %, canhave a boiling point in the range of ˜400° F. (˜204° C.) to ˜750° F.(˜399° C.).

Examples of Reaction System Configurations

FIG. 1 shows an example of a reaction system suitable for processing ofa catalytic slurry oil to form one or more naphthenic productcompositions. The reaction system example in FIG. 1 corresponds to asingle stage hydrotreating system. In FIG. 1, a feed 105 includingcatalytic slurry oil is passed into a filter 110 to form a filtered feed115 with a reduced or minimized content of catalyst fines. The filteredfeed 115 is then passed into a hydrotreating stage 120 along withhydrogen 101. In FIG. 1, hydrogen 101 is introduced into the feed priorto entering the hydrotreating stage 120, but any other convenient methodfor introducing hydrogen into the hydrotreating stage 120 can also beused. The hydrotreating stage 120 produces a hydrotreated effluent 125.The hydrotreated effluent 125 can then be fractionated 130 to generate avariety of products. The fractionated products can include one or morenaphtha fractions 141 and one or more light diesel fractions 143. Boththe naphtha fraction(s) 141 and the light diesel fraction(s) 143correspond to fractions with a sulfur content of 15 wppm or less, or 10wppm or less, or 5 wppm or less, such as down to substantially no sulfurcontent. A bottoms fraction 149 corresponding to the 1050° F.+(566° C.+)portion of the hydrotreated effluent can also be formed. Additionally,one or more naphthenic product compositions can be formed. For example,the 260° C. to 566° C. portion of the hydrotreated effluent can befractionated to form naphthenic oils having a viscosity of 2.5 cSt(132), 6 cSt (134), 12 cSt (136), and 35 cSt (138). Optionally, the 2.5cSt naphthenic oil can instead correspond to a heavy diesel fraction.Optionally, the 6 cSt naphthenic oil can instead correspond to a lightgas oil fraction.

FIG. 2 shows another type of configuration, where solvent deasphaltingis used in place of filtration. In FIG. 2, the feed 105 is introducedinto a solvent deasphalting stage 250, along with a deasphalting solvent251. The solvent deasphalting stage 250 can generate a deasphalted oil255 and an asphalt or rock fraction 259. The rock fraction 259 caninclude the catalyst fines or particles from the catalytic slurry oil.The deasphalted oil 255 can then be introduced into hydrotreating stage120, along with hydrogen 101. The resulting hydrotreated effluent 125can be fractionated 130 to form a variety of products. In some aspects,deasphalting stage 250 can also remove some multi-ring structures thatare difficult to hydroprocess, thus allowing the hydrotreatingconditions in hydrotreating stage 120 to be milder.

FIG. 3 shows still another option for removing particles from a catalystslurry oil prior to hydrotreatment. In FIG. 3, a vacuum fractionation360 is performed on the feed 105 to form a bottoms fraction 369 andfractionated feed 365. It is noted vacuum fractionator 360 could be usedto directly form a fractionated feed 365 from a FCC effluent, as opposedto first performing an atmospheric fractionation to form a catalyticslurry oil and then vacuum fractionating the feed 105 that includes thecatalytic slurry oil. The fractionated feed 365 can then be passed intohydrotreating stage 120 along with hydrogen 101.

FIGS. 1 to 3 show examples of single stage hydroprocessingconfigurations. The types of configurations shown in FIGS. 1 to 3 canalso be incorporated into a multi-stage configuration, such as aconfiguration that includes a second aromatic saturation stage.

FIG. 4 shows an example of a multi-stage configuration for producingnaphthenic product compositions. In FIG. 4, a feed including a catalyticslurry oil is filtered to form a filtered feed 415. The filtered feed415 can then be hydrotreated in hydrotreating stage 420. The resultinghydrotreated effluent 425 can be fractionated in an atmosphericfractionator 480 to produce a variety of fractions. The fractions caninclude a naphtha fraction 481, a diesel fraction 483, a heavy dieselfraction 482, a light gasoil 484, and a bottoms fraction 485. Thebottoms fraction 485 can correspond to a 343° C.+ fraction, or a 370°C.+ fraction, or a 400° C.+ fraction, or another convenient type offraction that can be generated from atmospheric distillation.

In the configuration shown in FIG. 4, heavy diesel fraction 482 andlight gasoil 484 are passed into aromatic saturation stage 490. Bottomsfraction 485 is passed into a vacuum fractionator 450 for furtherfractionation. For example, bottoms fraction 485 can be fractionated 460to form a 12 cSt naphthenic base oil 466, a 35 cSt naphthenic base oil468, and a 566° C.+ bottoms 469. The naphthenic base oil fractions 466and 468 can then also be passed into aromatic saturation stage 490 forfurther hydroprocessing. The bottoms 469 can be used for coke productionand/or a portion can also be passed into aromatic saturation stage 490.The separate fractions for passage into aromatic saturation stage 490are noted based on aspects where block processing is used to separatelyexpose the fractions to aromatic saturation conditions. Optionally, oneor more wide cut fractions can be passed into aromatic saturation stage490, rather than forming distinct fractions prior to aromaticsaturation.

In other aspects, the additional vacuum fractionator 460 can be omitted,and the bottoms fraction 485 plus one or more of diesel fraction 483,heavy diesel fraction 482, and light gasoil fraction 484 can be passedinto aromatic saturation stage 490 for further hydroprocessing.

Aromatic saturation stage 490 can generate an effluent 495 that is thenfractionated 430 to form a variety of products. The variety of productscan include, for example, a naphtha fraction 441, a diesel fraction 443,one or more light naphthenic base oils 432, and one or more heavynaphthenic base oils 436.

FIG. 5 shows a variation on the configuration in FIG. 1. In FIG. 5, oneor more the naphthenic product compositions, such as products 132, 134,136, or 138, can undergo aromatic extraction in a solvent processingstage 550. This can produce raffinate products 535 with reduced orminimized aromatic contents. This can also produce one or more extractfractions 539.

EXAMPLES

Various examples are provided below to demonstrate hydroprocessing ofcatalytic slurry oils (without dewaxing) to form naphthenic productcompositions. In the various examples below, representative catalyticslurry oil feeds were used. Table 1 shows the range of properties forthe representative catalytic slurry oil feeds.

TABLE 1 Typical Catalytic Slurry Oil Properties Hydrogen Mass %7.26-7.38 Sulfur Mass % 3.0-3.1 Nitrogen Mass % 0.16-0.25 Micro CarbonResidue Mass % 12.5 Density at 15° C. (calculated) g/cm3  1.12 KinematicViscosity, 100° C. cSt 29.6-31.6 SIMDIS ° C. 10% 355-357 50% 422-425 90%534-541 Composition Wt % Saturates  6.2 Aromatics + Sulfides + Polars93.8

Example 1—Naphthenic Base Oils from Hydrotreating Second Example ofSingle Stage Upgrading Process

A catalytic slurry oil feed within the typical ranges described in Table1 was exposed to a stacked bed of commercially available hydrotreatingcatalysts under conditions corresponding to 2400 psig (˜16.5 MPa-g) ofH2, a LHSV of 0.24 hr-1, and a hydrogen treat gas rate of 10,500 scf/bbl(˜1800 m3/m3). The temperature during hydrotreatment was selected togenerate a total liquid product (C5+) with a sulfur content of roughly150 wppm. The resulting hydrotreated effluent was then fractionated toform a fuels cut (including naphtha and diesel boiling rangecomponents), a 566° C.+ bottoms fraction, and four naphthenic base oilcompositions. The naphthenic base oil compositions corresponded to alight naphthenic base oil with a kinematic viscosity at 100° C. of 2.9cSt; a medium naphthenic base oil with a kinematic viscosity at 100° C.of 6.0 cSt; a first heavy naphthenic base oil with a kinematic viscosityat 100° C. of 18.7 cSt; and a second heavy naphthenic base oil with akinematic viscosity at 100° C. of 58.4 cSt. Table 2 shows the propertiesof the naphthenic base oils.

TABLE 2 Naphthenic Base Oils from Single Stage Hydrotreatment Sample 1 23 4 Sulfur (wppm) 19.1 107 341 396 Nitrogen (wppm) 1.6 31.4 164 209 KV @40° C. 16.10 87.78 970 11002 (cSt) KV @ 70° C. 83.57 423.92 (cSt) KV @100° C. 2.91 5.98 18.70 58.41 (cSt) Viscosity Index −45 −153 −232 −323Density @15° C. 0.9544 0.9910 1.0098 1.0266 (g/cm3) SIMDIS (° C.)T5/T50/T95 307/ 345/ 395/ 419/ 339/358 378/407 429/480 480/553 TotalAromatics 59 78 78 83 (D2502) (wt %)

Example 2—Naphthenic Base Oils from Hydrotreating and Solvent Extraction

Naphthenic base oils 1 and 2 from Table 2 were further processed usingsolvent extraction in N-Methyl Pyrrolidone. The solvent extractionconditions are shown in Table 5, along with a comparison of theproperties of the naphthenic base oil prior to extraction and theresulting raffinate naphthenic base oil. As shown in Table 3, solventextraction can reduce the aromatic content of the raffinate naphthenicbase oil while also improving the viscosity index of the raffinatenaphthenic base oil.

TABLE 3 Solvent Extracted Naphthenic Base Oils Naphthenic Base Oil 1Naphthenic Base Oil 2 Before After NMP Before After NMP ExtractionExtraction Extraction Extraction KV @40° C. 16.10 15.75 87.78 57.86(cSt) KV @100° C. 2.91 2.94 5.98 5.66 (cSt) Extraction ConditionsExtraction Tower 60 50 Top T (° C.) Extraction Tower 50 40 Bottom T (°C.) Dosage (vol/vol %) 50 100 H2O (wt %) 2.5 6 Yield 42.9 28 Aromatics(wt %) 59 44 78 39 Carbon, mol % (D2140) Cp 22 23 21 29 Cn 52 57 39 56Ca 26 20 39 15

Example 3—Two Stage Naphthenic Oil Production Via Hydrotreating andAromatic Saturation

A feed within the ranges of Table 1 was hydrotreated under conditionssimilar to those used in Example 1. The resulting hydrotreated effluentwas fractionated, which included formation of a 3.6 cSt naphthenic baseoil composition. The 3.6 cSt naphthenic base oil had an aromaticscontent of roughly 60 wt %, a paraffin content of 2.3 wt %, and aviscosity index of roughly −100. The 3.6 cSt naphthenic base oilcomposition was then exposed to several types of aromatic saturationcatalysts under aromatic saturation conditions that included 2000 psig(˜13.8 MPa-g) of H2 and a hydrogen treat gas rate of 4600-5000 scf/bbl(˜820-890 m3/m3). The temperature and LHSV were varied between roughly500° F. (260° C.) and 575° F. (302° C.) as shown in FIG. 7.

Three different aromatic saturation catalysts were used for aromaticsaturation. One aromatic saturation catalyst corresponded to acommercially available aromatic saturation catalyst that included noblemetals on a refractory support. The second aromatic saturation catalystcorresponded to 0.6 wt % Pt on an alumina bound USY support. The thirdaromatic saturation catalyst corresponded to 0.9 wt % Pd and 0.3 wt % Pton an alumina bound MCM-41 support.

During aromatic saturation, the commercially available aromaticsaturation catalyst was effective for substantially complete saturationof the aromatics in the feed, resulting in naphthenic base oils withroughly 73 mol % to 76 mol % naphthenic carbons, 20 mol % to 23 mol %paraffinic carbons, and 3 mol % to 4 mol % aromatics carbons (ASTMD2140). The naphthenic base oils had a viscosity index of between −4 and7 and a kinematic viscosity at 100° C. of roughly 3.0.

The catalyst with 0.6 wt % Pt supported on alumina bound USY resulted inslightly less saturation of aromatic rings relative to the commerciallyavailable catalyst. At temperatures of roughly 280° C. and roughly 300°C., the 0.6 wt % Pt/USY catalyst generated an aromatic saturationeffluent similar to the commercial catalyst, including 73 mol % to 75mol % naphthenic carbons, 20 mol % to 23 mol % paraffinic carbons, and 4mol % to 5 mol % aromatic carbons. The viscosity index of the effluentfrom the 0.6 wt % Pt/USY catalyst was between 8 and 26 at thetemperatures of 280° C. and 300° C., which is higher than the range forthe commercially available catalyst. The resulting kinematic viscosityat 100° C. was also lower, corresponding to roughly 2.7 to 2.9 cSt. Itis noted that the processing at 260° C. resulted in substantially lessaromatic saturation, so that the aromatic carbon content was roughly 10mol %, with a corresponding viscosity index of roughly −18. Although the0.6 wt % Pt/USY catalyst appeared to have modestly lower activity foraromatic saturation, the viscosity index of the resulting effluentappeared to be higher.

The catalyst with 0.9 wt % Pd and 0.3 wt % Pd on alumina bound MCM-41appeared to have still lower activity for aromatic saturation at thetemperatures and space velocities shown in FIG. 7. At the temperaturesof roughly 280° C. and 300° C., the Pt+Pd/MCM-41 catalyst producedeffluents with aromatic contents ranging from roughly 7 wt % to 28 wt %.The naphthenic carbon content 63 mol % to 72 mol %, while the aromaticcarbon content was 6 mol % to 15 mol %. The paraffinic carbon contentremained at 22 mol % to 23 mol %. The viscosity index of the effluentsranged from −11 to 16, with kinematic viscosities of roughly 2.8 to 3.0cSt. Similar to the 0.6 wt % Pt/USY catalyst, performing the aromaticsaturation at 260° C. resulted in lower aromatic saturation. At 260° C.,the effluent had a viscosity index of −31 with a kinematic viscosity of3.2 cSt.

Example 4—Two Stage Upgrading Via Hydrotreating and Aromatic Saturation

A feed within the ranges of Table 1 was hydrotreated under conditionssimilar to those used in Example 1. The resulting hydrotreated effluentwas fractionated, which included form various naphthenic base oilcompositions. A 14.28 cSt naphthenic base oil cut was furtherhydrotreated over a bulk metal hydrotreating catalyst and then over acommercial aromatic saturation catalyst after the separation of the H2S,NH3, and C1-C4 light ends. Hydrotreating was conducted under theconditions that included 2000 psig (˜13.8 MPa-g) of H2, a hydrogen treatgas rate of 10,000 scf/bbl (˜1781 m3/m3), an LHSV of roughly 1.0 hr-1,and a temperature of 375° C. Aromatic saturation was conducted under theconditions that included 2000 psig (˜13.8 MPa-g) of H2, a hydrogen treatgas rate of 10,000 scf/bbl (˜1781 m3/m3), an LHSV of roughly 0.25 hr-1,and a temperature of either roughly 225° C. or 250° C. Liquid productscollected from AROSAT were distilled to obtain naphthenic oils with anominal IBP of 700° F.+ fraction.

Properties of the resulting naphthenic base oils, listed in Table 4,show that the 2-stage process has produced naphthenic base oils with akinematic viscosity of roughly 9 cSt at 100° C. and a VI of −54.Aromatic reduction was greater than 99.5%. The products contain 27-28mol % paraffinic carbon, 69 mol % naphthenic carbon and 3-4 mol %aromatic carbon.

TABLE 4 Two Stage Upgrading Feed and Products Feed kV @ 60° C. 111.3 kV@100° C. 14.28 VI −244 Aromatics, wt % 76.5 Carbon Type, mole % (D2140)Cp 12 Cn 54 Ca 35 HDT Temp, ° C. 360-375 Pressure, psig 2000 LHSV, 1/h1.0 H2/Oil, scf/bbl 10000 AROSAT Temp, ° C. 225 250 Pressure, psig 2000LHSV, 1/h 0.25 H2/Oil, scf/bbl 10000 Product kV @ 40° C. 155.9 148 kV @100° C. 9.13 8.9 VI −54.6 −53.1 Aromatics, wt % 0.36 0.25 Carbon Type,mole % (D2140) Cp 28 27 Cn 69 69 Ca 4 3

Example 5—Property Comparisons Versus Conventional Base Oils

FIG. 6 shows the percentage of naphthenic carbon versus viscosity indexfor the various base oils made using two stage hydroprocessing of acatalytic slurry oil, similar to the method described in Example 4(triangle data points). The resulting naphthenic base oils hadviscosities ranging from roughly 3.0 cSt to roughly 30 cSt. As shown inFIG. 6, the various naphthenic base oils had viscosity index values of30 or less, or 25 or less.

For comparison, the amount of naphthenic carbon versus viscosity indexis shown for a large number of naphthenic base oils made fromconventional naphthenic crude feeds (circle data points). Thecomparative data points correspond to data points that were available invarious types of literature. The dividing line between the two sets ofdata points demonstrates the unexpected disparity between the viscosityindex and naphthenic carbon content for the naphthenic oils formed usingconventional naphthenic feed versus naphthenic oils formed fromcatalytic slurry oil.

FIG. 10 provides another comparison between base oils made according toExample 4 and the comparative base oils shown in FIG. 6. In FIG. 10, theamount of paraffinic carbon according to ASTM D2140 is plotted versusthe weight percent of saturates in the base oils. As shown in FIG. 10,the base oils made from catalytic slurry oil included 30 mol % or lessparaffinic carbon, while the conventionally made naphthenic base oilsincluded 33 mol % or more paraffinic carbon, regardless of the amount ofsaturates in the base oils.

As still another type of comparisons, FIG. 8 and FIG. 9 show pour pointversus kinematic viscosity for the two stage hydroprocessing base oilsmade from catalytic slurry oil (triangle data points). FIG. 8corresponds to kinematic viscosity at 100° C., while FIG. 9 correspondsto kinematic viscosity at 40° C. For comparison, base oils made fromcatalytic slurry oil according to the methods described in U.S. Pat.Nos. 8,585,889, 8,691,076, or 8,911,613 are also shown (circle datapoints). The comparative base oils in FIG. 8 and FIG. 9 correspond tobase oils that were exposed to catalytic dewaxing as part of thehydroprocessing to form the base oils.

As shown in FIG. 8 and FIG. 9, the comparative base oils have higherkinematic viscosities at comparable pour point than the base oils madeaccording to the methods described herein. In addition to being dewaxed,the comparative base oils also tend to have one or more otherdifferences in property, such as a naphthenic carbon content less than60 mol % and/or a viscosity index greater than 30 and/or an aromaticscontent of greater than 5.0 wt %.

ADDITIONAL EMBODIMENTS Embodiment 1

A method for processing a product fraction from a fluid catalyticcracking (FCC) process, comprising: exposing a feed comprising acatalytic slurry oil, the feed comprising a 343° C.+ portion, to ahydrotreating catalyst under effective hydrotreating conditions to forma hydrotreated effluent, the 343° C.+ portion of the feed comprising adensity of 1.06 g/cm3 or more, and exposing at least a portion of the343° C.+ portion to a hydroprocessing catalyst under effectivehydroprocessing conditions to form a hydroprocessed effluent, wherein aC5+ portion of the hydroprocessed effluent comprises 50 mol % or morenaphthenic carbons and 500 wppm or less of sulfur, the C5+ portion ofthe hydroprocessed effluent optionally comprising a density of 1.00g/cm3 or less.

Embodiment 2

The method of Embodiment 1, wherein the C5+ portion of thehydroprocessed effluent comprises 60 mol % or more of naphthenic carbons(or 65 mol % or more, or 70 mol % or more), or wherein the C5+ portionof the hydroprocessed effluent comprises 30 mol % or less of paraffiniccarbons (or 25 mol % or less), or a combination thereof.

Embodiment 3

The method of any of the above embodiments, wherein the C5+ portion ofthe hydroprocessed effluent comprises 50 wt % or more saturates (or 60wt % or more, or 70 wt % or more).

Embodiment 4

The method of any of the above embodiments, wherein the C5+ portion ofthe hydroprocessed effluent comprises 15 wt % or less aromatics (or 10wt % or less), or wherein the C5+ portion of the hydroprocessed effluentcomprises 15 mol % or less of aromatic carbons (or 10 mol % or less, of5.0 mol % or less), or a combination thereof.

Embodiment 5

The method of any of the above embodiments, wherein the C5+ portion ofthe hydroprocessed effluent comprises a kinematic viscosity at 100° C.of 2.0 cSt to 30 cSt, a viscosity index of 25 or less, or a combinationthereof.

Embodiment 6

The method of any of the above embodiments, further comprisingfractionating the C5+ portion of the hydroprocessed effluent to form oneor more naphthenic base oil compositions, the one or more naphthenicbase oil compositions comprising: a) at least one naphthenic base oilcomposition comprising a kinematic viscosity at 100° C. of 1.5 cSt to4.0 cSt, a viscosity index of −20 to 25, and a T5 distillation point of270° C. or more; b) at least one naphthenic base oil compositioncomprising a kinematic viscosity at 100° C. of 4.5 cSt to 8.0 cSt, aviscosity index of −50 to 0, and a T5 distillation point of 300° C. ormore; c) at least one naphthenic base oil composition comprising akinematic viscosity at 100° C. of 8.0 cSt to 20 cSt, a viscosity indexof −80 to −20, and a T5 distillation point of 330° C. or more; d) atleast one naphthenic base oil composition comprising a kinematicviscosity at 100° C. of 25 cSt to 75 cSt, a viscosity index of −120 to−50, and a T5 distillation point of 360° C. or more; e) a combination oftwo or more of a), b), c), and d); or f) a combination of three or moreof a), b), c), and d).

Embodiment 7

The method of Embodiment 6, wherein the one or more naphthenic base oilcompositions comprise 60 mol % or more of naphthenic carbons (or 65 mol% or more, or 70 mol % or more); or 30 mol % or less paraffinic carbons(or 25 mol % or less); or 50 wt % or more saturates (or 60 wt % or more,or 70 wt % or more), or 15 mol % or less of aromatic carbons (or 10 mol% or less, of 5.0 mol % or less); or a combination of two or morethereof, or three or more thereof.

Embodiment 8

The method of any of the above embodiments, wherein the hydroprocessedeffluent is formed without exposing the catalytic slurry oil to adewaxing catalyst under catalytic dewaxing conditions, or wherein thehydroprocessed effluent is formed without exposing the catalytic slurryoil to a catalyst comprising a zeotype framework in the presence ofhydrogen under hydroprocessing conditions, or wherein the effectivehydroprocessing conditions comprise fixed bed hydroprocessingconditions, or a combination thereof.

Embodiment 9

The method of any of the above embodiments, wherein the feed comprises afraction from a fluid catalytic cracking process having a T5distillation point of 343° C. or more, a T95 distillation point of 566°C. or less, or a combination thereof, the method optionally furthercomprising treating the fraction from the fluid catalytic crackingprocess to form a treated fraction comprising a particle content of 500wppm or less of particles having a size of 25 μm or more (or 100 wppm orless), the catalytic slurry oil comprising at least a portion of thetreated fraction.

Embodiment 10

A naphthenic base oil composition, comprising 500 wppm or less sulfur,18 mol % to 30 mol % paraffinic carbons, 50 mol % or more of naphtheniccarbons, a kinematic viscosity at 100° C. of 2.0 cSt to 30 cSt, aviscosity index of 25 or less, and a T5 distillation point of 260° C. ormore.

Embodiment 11

The composition of Embodiment 10, wherein i) the composition comprises70 mol % or more naphthenic carbons and a viscosity index of −50 to 25;ii) the composition comprises 60 mol % to 70 mol % naphthenic carbonsand a viscosity index of −100 to 10; or iii) the composition comprises50 mol % to 60 mol % naphthenic carbons and a viscosity index of −150 to−20.

Embodiment 12

The composition of Embodiment 10, wherein the composition comprises 25mol % to 30 mol % paraffinic carbons, 65 mol % to 75 mol % of naphtheniccarbons, a kinematic viscosity at 100° C. of 8.0 cSt to 15 cSt, and aviscosity index of −40 or less (or −50 or less).

Embodiment 13

The composition of any of Embodiments 10-12, wherein the compositioncomprises 50 wt % or more saturates (or 60 wt % or more, or 70 wt % ormore); or wherein the composition comprises 15 wt % or less aromatics(or 10 wt % or less, or 5 wt % or less); or wherein the compositioncomprises 15 mol % or less of aromatic carbons (or 10 mol % or less, of5.0 mol % or less), or a combination thereof.

Embodiment 14

A composition formed according to the method of any of Embodiments 1-9.

Embodiment 15

A naphthenic base oil composition, comprising 500 wppm or less sulfur,18 mol % to 30 mol % paraffinic carbons and 60 mol % or more ofnaphthenic carbons, the naphthenic base oil composition furthercomprising: a) a kinematic viscosity at 100° C. of 1.5 cSt to 4.5 cSt, aviscosity index of −20 to 25, and a T5 distillation point of 270° C. ormore; b) a kinematic viscosity at 100° C. of 4.5 cSt to 8.0 cSt, aviscosity index of −50 to 0, and a T5 distillation point of 300° C. ormore; c) a kinematic viscosity at 100° C. of 8.0 cSt to 20 cSt, aviscosity index of −80 to −20, and a T5 distillation point of 330° C. ormore; or d) a kinematic viscosity at 100° C. of 20 cSt to 75 cSt, aviscosity index of −120 to −50, and a T5 distillation point of 360° C.or more.

When numerical lower limits and numerical upper limits are listedherein, ranges from any lower limit to any upper limit are contemplated.While the illustrative embodiments of the invention have been describedwith particularity, it will be understood that various othermodifications will be apparent to and can be readily made by thoseskilled in the art without departing from the spirit and scope of theinvention. Accordingly, it is not intended that the scope of the claimsappended hereto be limited to the examples and descriptions set forthherein but rather that the claims be construed as encompassing all thefeatures of patentable novelty which reside in the present invention,including all features which would be treated as equivalents thereof bythose skilled in the art to which the invention pertains.

The present invention has been described above with reference tonumerous embodiments and specific examples. Many variations will suggestthemselves to those skilled in this art in light of the above detaileddescription. All such obvious variations are within the full intendedscope of the appended claims.

1. A method for processing a product fraction from a fluid catalyticcracking (FCC) process, comprising: exposing a feed comprising acatalytic slurry oil, the feed comprising a 343° C.+ portion, to ahydrotreating catalyst under effective hydrotreating conditions to forma hydrotreated effluent, the 343° C.+ portion of the feed comprising adensity of 1.06 g/cm3 or more, and exposing at least a portion of the343° C.+ portion to a hydroprocessing catalyst under effectivehydroprocessing conditions to form a hydroprocessed effluent, wherein aC5+ portion of the hydroprocessed effluent comprises 50 mol % or morenaphthenic carbons and 500 wppm or less of sulfur.
 2. The method ofclaim 1, wherein the C5+ portion of the hydroprocessed effluentcomprises 60 mol % or more of naphthenic carbons, or wherein the C5+portion of the hydroprocessed effluent comprises 30 mol % or less ofparaffinic carbons, or a combination thereof.
 3. The method of claim 1,wherein the C5+ portion of the hydroprocessed effluent comprises 50 wt %or more saturates.
 4. The method of claim 1, wherein the C5+ portion ofthe hydroprocessed effluent comprises 15 wt % or less aromatics, orwherein the C5+ portion of the hydroprocessed effluent comprises 15 mol% or less of aromatic carbons, or a combination thereof.
 5. The methodof claim 1, wherein the C5+ portion of the hydroprocessed effluentcomprises a kinematic viscosity at 100° C. of 2.0 cSt to 30 cSt, aviscosity index of 25 or less, or a combination thereof.
 6. The methodof claim 1, wherein the C5+ portion of the hydroprocessed effluentcomprises 100 wppm or less of sulfur.
 7. The method of claim 1, furthercomprising fractionating the C5+ portion of the hydroprocessed effluentto form one or more naphthenic base oil compositions, the one or morenaphthenic base oil compositions comprising: a) at least one naphthenicbase oil composition comprising a kinematic viscosity at 100° C. of 1.5cSt to 4.0 cSt, a viscosity index of −20 to 25, and a T5 distillationpoint of 270° C. or more; b) at least one naphthenic base oilcomposition comprising a kinematic viscosity at 100° C. of 4.5 cSt to8.0 cSt, a viscosity index of −50 to 0, and a T5 distillation point of300° C. or more; c) at least one naphthenic base oil compositioncomprising a kinematic viscosity at 100° C. of 8.0 cSt to 20 cSt, aviscosity index of −80 to −20, and a T5 distillation point of 330° C. ormore; d) at least one naphthenic base oil composition comprising akinematic viscosity at 100° C. of 25 cSt to 75 cSt, a viscosity index of−120 to −50, and a T5 distillation point of 360° C. or more; e) acombination of two or more of a), b), c), and d); or f) a combination ofthree or more of a), b), c), and d).
 8. The method of claim 7, whereinthe one or more naphthenic base oil compositions comprise 60 mol % ormore of naphthenic carbons, or wherein the one or more naphthenic baseoil compositions comprise 30 mol % or less paraffinic carbons, or acombination thereof.
 9. The method of claim 7, wherein the one or morenaphthenic base oil compositions comprise 50 wt % or more saturates, orwherein the one or more naphthenic base oil compositions comprise 15 mol% or less of aromatic carbons, or a combination thereof.
 10. The methodof claim 1, wherein the hydroprocessed effluent is formed withoutexposing the catalytic slurry oil to a dewaxing catalyst under catalyticdewaxing conditions, or wherein the hydroprocessed effluent is formedwithout exposing the catalytic slurry oil to a catalyst comprising azeotype framework in the presence of hydrogen under hydroprocessingconditions, or a combination thereof.
 11. The method of claim 1, whereinthe effective hydroprocessing conditions comprise fixed bedhydroprocessing conditions.
 12. The method of claim 1, wherein the feedcomprises a fraction from a fluid catalytic cracking process having a T5distillation point of 343° C. or more, a T95 distillation point of 566°C. or less, or a combination thereof.
 13. The method of claim 12,further comprising treating the fraction from the fluid catalyticcracking process to form a treated fraction comprising a particlecontent of 500 wppm or less of particles having a size of 25 μm or more,the catalytic slurry oil comprising at least a portion of the treatedfraction.
 14. A naphthenic base oil composition, comprising 500 wppm orless sulfur, 18 mol % to 30 mol % paraffinic carbons, 50 mol % or moreof naphthenic carbons, a kinematic viscosity at 100° C. of 2.0 cSt to 30cSt, a viscosity index of 25 or less, and a T5 distillation point of260° C. or more.
 15. The composition of claim 14, wherein thecomposition comprises 70 mol % or more naphthenic carbons and aviscosity index of −50 to
 25. 16. The composition of claim 14, whereinthe composition comprises 60 mol % to 70 mol % naphthenic carbons and aviscosity index of −100 to
 10. 17. The composition of claim 14, whereinthe composition comprises 50 mol % to 60 mol % naphthenic carbons and aviscosity index of −150 to −20.
 18. The composition of claim 14, whereinthe composition comprises 25 mol % to 30 mol % paraffinic carbons, 65mol % to 75 mol % of naphthenic carbons, a kinematic viscosity at 100°C. of 8.0 cSt to 15 cSt, and a viscosity index of −40 or less.
 19. Thecomposition of claim 14, wherein the composition comprises 50 wt % ormore saturates.
 20. The composition of claim 14, wherein the compositioncomprises 15 wt % or less aromatics, or wherein the compositioncomprises 15 mol % or less of aromatic carbons, or a combinationthereof.
 21. The composition of claim 14, wherein the compositioncomprises 5 mol % or less aromatic carbons, or wherein the compositioncomprises 1.0 wt % or less aromatics, or a combination thereof.
 22. Anaphthenic base oil composition, comprising 500 wppm or less sulfur, 18mol % to 30 mol % paraffinic carbons and 60 mol % or more of naphtheniccarbons, the naphthenic base oil composition further comprising: a) akinematic viscosity at 100° C. of 1.5 cSt to 4.5 cSt, a viscosity indexof −20 to 25, and a T5 distillation point of 270° C. or more; b) akinematic viscosity at 100° C. of 4.5 cSt to 8.0 cSt, a viscosity indexof −50 to 0, and a T5 distillation point of 300° C. or more; c) akinematic viscosity at 100° C. of 8.0 cSt to 20 cSt, a viscosity indexof −80 to −20, and a T5 distillation point of 330° C. or more; or d) akinematic viscosity at 100° C. of 20 cSt to 75 cSt, a viscosity index of−120 to −50, and a T5 distillation point of 360° C. or more.